Plug and Gun Apparatus and Method for Cementing and Perforating Casing

ABSTRACT

An apparatus is used in cementing and perforating casing in a borehole. A cement head disposed on the casing has first and second containers. A first plug positioned in the first container deploys from the cement head in the casing in advance of cement slurry. An assembly positioned in the second container deploys from the cement head in the casing after the cement slurry. The first plug lands on a float collar on the casing, and a breachable passage in the first plug opens and allows the cement slurry to pass into the borehole annulus. The assembly has a wiper and has one or more charges. The wiper wipes the casing as the assembly is displaced down the casing with displacing fluid. Eventually, the assembly lands at the first plug, and hydraulic pressure applied in the casing activates the one or more charges to perforate the casing.

BACKGROUND OF THE DISCLOSURE

Deviated or horizontal wells drilled in a formation typically have a casing cemented in the borehole. The casing and surrounding cement are perforated with holes to provide communication between the casing and the surrounding formation. Using such perforations, operators can perform any number of operations, such as hydraulic fracturing or dispensing acid or other chemicals into the producing formation. Additionally, the perforations can be used for production flow into a producing string disposed in the casing during producing operations.

In wellbore construction and completion operations, a wellbore is formed to access hydrocarbon-bearing formations (e.g., crude oil and/or natural gas) by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill string. To drill within the wellbore to a predetermined depth, the drill string is often rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is hung from the wellhead. A cementing operation is then conducted in order to fill the annulus with cement. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.

Once the initial or surface casing has been cemented, the wellbore may be extended and another string of casing or liner may be cemented into the wellbore. This process may be repeated until the wellbore intersects the formation. Once the formation has been produced and depleted, cement plugs may be used to abandon the wellbore. If the wellbore is exploratory, tests may be performed and then the wellbore abandoned.

Not all wells that are drilled and casing strings cemented in place during the well operation are problematic. Conversely, primary cementing of problematic wells has historically been inefficient to unobtainable by manipulation of the traditional variables. What can be recorded today to effectively measure the success or failure of a primary cement job is not adequate for cementing problematic wells. Understanding the objectives of a primary cement job, being able to execute the primary cement job and adequately interpreting the results have ultimately been the criteria of a success or a failure. Whether success is a leak-off test, open-hole kick-off plug, isolation of a hydrocarbon bearing zone of interest, or a fresh water zone that must be hydraulically or mechanically isolated and protected, the tools and methods that operators and service companies employ today that can be controlled and monitored are not always enough to provide the expected nor the desired results.

Several techniques are currently in use to create perforations in casing to create an initial flow path. Most of the techniques require a workover rig or a coiled tubing (CT) unit.

For example, Tubing Conveyed Perforating (TCP) is a common technique for creating an initial flow path in casing after cementing and is widely offered by major service companies. In the TCP techniques, tubing conveyed perforating guns are run on coil tubing or conventional coupled tubing in the casing with a workover rig to perforate the casing using single or multiple guns. Coil tubing is the quicker method of running and retrieving the TCP guns, but it is also more expensive than using a workover rig. Using conventional coupled tubing with a workover rig requires more time to trip the pipe and guns into and out of the well, but it is less expensive than coil tubing. Although creating the flow paths with tubing conveyed perforating gun is the most reliable method, it is also the most cost intensive.

Hydraulic sleeves are also offered by major service companies to create an initial flow path in casing after cementing. In this technique, a hydraulic sleeve is run with the casing and is an integral part of the casing string. This eliminates costs associated with using coil tubing or a workover rig. The sleeve is placed close to the bottom of the casing near the float collar.

During the cement job to cement the casing in the borehole, the tail of cement is lightened up or retarded to prevent the cement at the sleeve from fully setting up. When operators are ready to start the completion operations, operators pressure up the casing to open the hydraulic sleeve and establish the flow path. In some cases, operators are unable to open the hydraulic sleeve and/or establish a high enough flow rate for pump down operations. In this case, operators must use TCP guns to create the flow path needed at an additional cost. As a result, reliability and a poor cement job in the lower portion of the wellbore are some disadvantages of this method.

In another technique, an externally-mounted perforating gun system is used to create the initial flow path. Such as system is offered by Sage Riders Inc. as its Easy Rider System. Additionally, U.S. Pat. No. 7,635,027 discloses an externally-mounted perforating gun mounted on the casing.

In this system, the perforating gun is mounted externally on the casing string. When run downhole, the perforating gun is oriented to fire three shots per foot (spf) into the formation and to fire three spf into the casing to create the holes in the casing for the initial flow path. Because the perforating gun is mounted externally on the casing string, this type of system increases the effective O.D. of the lower joints of the casing so the system requires a bigger borehole to be drilled.

To minimize the effective O.D., operators may use a small O.D. gun (e.g., about 1 9/16″). This small size limits the performance of the shot charges and the resulting hole sizes produced in the casing. Also, the entrance holes in the casing are not aligned with the perforations into the formation. This misalignment increases friction and can hinder flow while pumping. Consequently, this system suffers difficulty in establishing a flow rate, getting enough flow rate for pump down operations, and in having a sufficient flow rate at reasonable pressures.

In another technique, a tractor-wireline combination system incorporates a wireline, perforating guns, and a tractor. The guns and the tractor are lowered into the wellbore via wireline. At the kick off point, the tractor is activated, and the guns are mechanically pulled with the tractor to the bottom of the wellbore. The guns are logged on depth. Eventually, the formation is perforated using the guns.

Initially, this system was used as a method to eliminate the costs associated with a coil tubing/TCP type of system. Also, this method allowed the wellbore to be perforated precisely and according to design. The drawbacks have proven to be substantial, as this system has high failure rates and is very time consuming to implement. Accordingly, demand for this system is very low due to these problems.

In yet other techniques, e-coil (coil tubing with wireline inside) can be utilized to perforate the bottom set of perforations, and a wet shoe can be used to create the initial flow path after cementing. During the casing cement job, the wet shoe requires a fluid spacer be run below the wiper plugs in conjunction with rupture discs. After the casing has been cemented in the wellbore, the drilling rig is moved off location. Frac equipment is put in place so the wellbore is made ready for stimulation. At this point, the rupture discs are ruptured, and the well is fractured through the casing shoe.

Problems associated with this method are related to the lack of cement in the lower wellbore and potential premature breakage of the rupture discs. Also, due to revised government regulations, this method may no longer be allowed in some places.

In still other techniques to perforate a wellbore, it is known in the art to couple a perforating gun with a wiper plug and deploy them down casing, as disclosed in U.S. Pat. No. 8,127,846. Finally, as disclosed in U.S. Pub. 2007/0227735, it is also known in the art to use a dart assembly having a dart for moving a well treatment fluid downhole and a perforating gun coupled to the dart. As the dart moves the well treatment fluid to a desired region of the well, the perforating gun is simultaneously moved to a desired location for perforating.

As can be seen, operators seek a technique to reliably and economically create a flow path for fluid from the inside of the casing through the formation in horizontal wells to allow pumping down other tools and/or operations. The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

In a method of cementing and perforating casing in a borehole, cement slurry is pumped down the casing and into an annulus of the borehole. An assembly having a wiper and at least one perforating charge is pumped down the casing behind the cement slurry. For example, a displacing fluid can be pumped down the casing after the assembly. Eventually, the assembly lands in the casing. Hydraulic pressure is applied in the casing, and the assembly perforates the casing when the at least one perforating charge is activated with the applied hydraulic pressure.

To pump the cement slurry down the casing and into the annulus of the borehole, a plug can be pumped down the casing in advance of the cement slurry. The plug can land in the casing. For example, the plug can be pumped with a spacer between the plug and the cement slurry, and the plug can land on a float collar disposed on the casing. Fluid communication can then open through the plug for further passage of the cement slurry.

Before perforating the casing, the cement slurry is at least permitted to cure in the annulus. Additionally, after landing the assembly in the casing, integrity of the casing can be tested by applying intermediate hydraulic pressure in the casing behind the assembly. Preferably, activation of the at least one perforating charge is delayed should the intermediate hydraulic pressure activate the at least one perforating charge.

In any event, the at least one perforating charge can be activated with the hydraulic pressure applied in the casing. Typically, the required pressure to activate the assembly is predetermined and is configured for the particular implementation. For example, one or more rupture discs or other temporary barriers in the assembly can separate the applied hydraulic pressure from a firing head. When a predetermined pressure level is reached, the one or more rupture discs can rupture to expose the firing head to the applied pressure. The firing head may also have one or more shear pins or other temporary connections holding it in place. The same, higher, or lower pressure level from the applied hydraulic pressure can break the one or more shear pins to move a firing pin of the firing head against a detonator.

After perforating the casing, additional operations can be performed. For example, at least a portion of the assembly can be retrieved from the casing after perforating the casing. A bridge plug can be deployed in the casing uphole of the perforation, and the casing can be perforated uphole using another perforating gun.

In one implementation, an apparatus used in cementing and perforating casing in a borehole has a top plug, a perforating gun, and a firing mechanism. The perforating gun is attached to the top plug and has one or more perforating charges. A fishing neck can be disposed on a proximal end of the perforating gun. A distal end of the perforating gun can thread to a top of the top plug, as a separate component. Alternatively, the top plug and the perforating gun are integrally formed together.

The firing mechanism disposed on the perforating gun is coupled to the one or more charges. The firing mechanism is in fluid communication with the casing and is activated hydraulically to detonate the one or more charges.

A bottom plug independent of the top plug can be deployed in the casing in advance of the top plug. This bottom plug has a breachable passage therethrough so cement slurry can pass through this bottom plug and into the borehole annulus once the bottom plug lands at a float collar on the casing.

The firing mechanism can include a detonator, a pin, and at least one temporary retainer or rupture discs. The detonator is connected to the one or more perforating charges, and the pin is exposed to a chamber and is movable toward the detonator. The one or more rupture discs separate the chamber from external pressure in the casing.

For its part, the pin can have at least one second temporary retainer or shear pin holding the pin away from the detonator. When exposed to the applied hydraulic pressure, the at least one second temporary retainer can release the pin at a higher level hydraulic pressure than used to break the at least one first temporary retainer.

In another implementation, an apparatus used in cementing and perforating casing in a borehole includes a cement head, a first plug, and an assembly. The cement head is disposed on the casing and has first and second containers. A first plug positions in the first container and deploys from the cement head in the casing in advance of cement slurry. The assembly positions in the second container and deploys from the cement head in the casing after the cement slurry. The first plug lands at a float collar on the casing, and a breachable passage in the first plug opens and allows the cement slurry to pass into the borehole annulus.

The assembly has a wiper and has one or more perforating charges. The wiper wipes the casing as the assembly is displaced down the casing with displacing fluid. Eventually, the assembly lands at the first plug, and hydraulic pressure applied in the casing activates the one or more charges to perforate the casing.

The assembly provides a reliable, positive method of establishing an initial flow path through the casing into the formation to allow for further pump-down operations to be performed during frac stages. The assembly can use a full size perforating gun with maximum performance charges. This provides the large hole size in the casing and the penetration into the formation that is required for maximum flow rates at reasonable pressures.

Since the perforation gun is pumped down on the assembly during the initial cementing of the casing, there are no costs associated with TCP, coil tubing, conventional tubing, workover rigs, or tractor deployment. The problems associated with each of these historical solutions are also eliminated because they are not used during perforating.

Additionally, the O.D. of the casing does not need to be changed. Therefore, no change in the drilling program should be required to drill a larger borehole needed when guns are attached externally to the casing as in other systems. Drilling a larger borehole may increase costs when additional drilling time is required. All of this is eliminated when the guns of the disclosed system are positioned inside the casing during the initial cementing job.

The foregoing summary is not intended to summarize each potential embodiment or every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A illustrates a well assembly for the present disclosure.

FIG. 1B illustrates a gun-on-plug assembly according to the present disclosure for creating an initial flow path in casing after cementing operations.

FIG. 2A schematically illustrates portions of the well assembly having a bottom plug and the gun-on-plug assembly in an initial stage of a cementing operation.

FIG. 2B schematically illustrates the well assembly with the bottom plug deployed during the cementing operation.

FIGS. 2C-2D schematically illustrate the well assembly with the gun-on-plug assembly deployed during the cementing operation.

FIG. 2E schematically illustrates the well assembly with the gun-on-plug assembly landed on the bottom plug during the cementing operation.

FIG. 2F schematically illustrates the well assembly with the gun-on-plug assembly forming perforations in the casing.

FIG. 3A schematically illustrates a wireline assembly retrieving the gun-on-plug assembly.

FIG. 3B schematically illustrates the wireline assembly deploying a conventional perforating gun after setting a bridge plug in the casing.

FIG. 4 illustrates components of a gun-on-plug assembly according to one embodiment of the present disclosure.

FIG. 5 illustrates an embodiment of a firing mechanism for the disclosed gun-on-plug assembly.

DETAILED DESCRIPTION OF THE DISCLOSURE

As shown in FIG. 1A, a wellhead 20 at a rig 16 is mounted on outer casing 12 deployed into a wellbore 10, and a casing adapter 23 connects a pressure control assembly 21 of the wellhead 20 to a cementing head 30. The pressure control assembly 21 typically includes a blowout preventer (BOP) 24, a rotating control device (RCD) 26, a variable choke valve, and other conventional components.

A fluid system 40 includes a cement pump 42, a mud pump 44, and other components typically used on a rig for drilling, cementing, and production operations. Various valves, spools, rotorary table, top drive, derrick, traveling block, drawworks, and other conventional components are included, but may not be discussed herein. In any event, the wellbore 10 may be a land based wellbore as shown, or it may be a subsea wellbore 10 with suitable modifications to the wellhead 20 and other components.

The cementing head 30 includes launchers 32 a-b and a manifold 36 having trunks, branches, shutoff valves 34, and like for selectively communicating fluid from a cementing pump 42 to the launchers 32 a-b. Each launcher 32 a-b may include a canister for housing a cementing plug and a gun-on-plug assembly (100: FIG. 1B) according to the present disclosure.

Each launcher 32 a-b has a retainer stem, valve, or latch 38 a-b operable to selectively retain the respective device in the launcher 32 a-b. The manifold 36 can connect at its lower end directly to the casing adapter 23 to bypass the launchers 32 a-b. Intermediate branches from the manifold 36 may connect by valves 34 between the launchers 32 a-b for deploying the respectively contained devices, wipers, etc. In fact, an upper branch of the manifold 36 can have a valve 34 connected above an upper launcher 32 b for deploying the gun-on-plug assembly (100: FIG. 1B) according to the present disclosure.

The outer casing 12 extends a distance in the borehole 10, and the inner casing 50 extends into the borehole 10 toward a lower, open hole section in the formation 18, which may be a hydrocarbon-bearing reservoir or an environmentally sensitive or unstable area in need of cementing.

The inner casing 50 can extend from a casing hanger 22 at the wellhead 20, or at least a portion can extend from a liner hanger (not shown) into the open hole section 15 of the wellbore 10. As shown, this open hole section 15 may be horizontal or deviated and can extend a considerable distance. The inner casing 50 typical includes a plurality of casing joints (not shown) connected together, such as by threaded connections, and may include centralizers (see e.g., 54: FIG. 2A). Toward its downhole end, the casing string 50 includes a float collar 60 and a float shoe 70.

Typically, the casing string 50 when run in hole to be cemented has the float shoe 70 on bottom and has the float collar 60 placed on the string 50 spaced out from bottom with one or two shoe joints of casing. The float shoe 70, float collar 60, and the “shoe joints” of casing 50 help to ensure a good cement job around the bottom of the casing string 50. There are various configurations of both the float shoe 70 and float collar 60, and their use is determined for a given implementation.

The shoe 70 allows for flow therethrough and is used to guide the end of the casing 50 into the borehole 10. The float collar 60 includes one or more check valves 62 for selectively sealing flow from the shoe 70 into the casing 50. The check valve 62 is operable to allow fluid flow from the casing 50 into the wellbore 10 and prevent reverse flow from the borehole 10 into the casing 50.

With the casing 50 positioned in the open hole section 15, operators can set the casing 50 in the borehole 10 by pumping cement down the inner bore 52 of the casing 50. Typically, a bottom wiper plug is pumped ahead of the cement to wipe the casing of mud and to create a barrier between the cement and drilling mud. This bottom plug has a rupture disk that will burst with about 500 psi when it lands on the float collar 60, allowing for the continued displacement of the cement slurry. The cement flows through the float collar 60, out the float shoe 70, around the outside of the casing 50, and back up the annulus in the borehole 10 surrounding casing 50. Once the desired amount of cement has been pumped, operators need to pump down a wiper mechanism to wipe the casing's inner bore of cement. Eventually, the cement sets in the annulus surrounding the casing 50. To perform further operations, it is necessary to create an initial flow path at the toe of the casing 50 so fluid can be pumped down the casing 50 and allowed to exit to the formation.

To create this initial flow path, operators use the gun-on-plug assembly 100 mentioned briefly above. As schematically shown in isolation in FIG. 1B, the assembly 100 includes a cementing wiper plug 110, a perforating gun 120, a firing mechanism 150, and a fishing neck 180. This assembly 100 is loaded in the cement head 30 at the surface and is pumped down during the cementing operations so it can be activated to perforate the casing 50 toward the toe and create the initial flow path.

Turning now to FIGS. 2A-2F, the cementing operation using the gun-on-plug assembly 100 will be described in more detail. Before commencing the cementing operation, components are installed in the cementing head 30 at the surface. FIG. 2A schematically illustrates portions of the well assembly having components configured in an initial stage of the cementing operation.

At the surface, for example, operators load the bottom plug 80 in a bottom plug launcher 32 a in the cement head 30. The retaining stem 38 a of the head 30 is fully screwed into the launcher 32 a to hold the bottom plug 80 in place. Operators make sure that the “tattle tail” (not shown) on the head 30 is reset so it will properly indicate when the bottom plug 80 has left the plug launcher 32 a during deployment.

Operators then load the gun-on-plug assembly 100 in the upper plug launcher 32 b of the cement head 30. Again, the retaining stem 38 b is fully screwed into the head 30 to hold the assembly 100 in place. Preferrably, the gun 120 of the assembly 100 uses a percusive type of detonantor and does not use an electrical detonator to avoid any issues with currents, wireless signals, interference, and the like at the rig.

As can be seen, the cement head 30 is a double plug container having two launchers 32 a-b with sufficient length that allows both the bottom cement plug 80 and the top plug 110 with attached gun 120 to be preloaded before the cementing operation begins. In general, the gun-on-plug assembly 100 may be about 7-feet long. For its part, the cement head 30 can be elongated to accommodate the assembly 100. Alternatively, the cement head 30 can have standard plug container and can include an adapted lubricator affixed thereon to accommodate the assembly 100.

Once prepared, the cement head 30 is then kept on standby as operators run the casing 50 in the well with the float collar 60 and the float shoe 70 properly in place to create a casing shoe joint assembly of about 40 to 80 ft. at the toe of the wellbore 10. Once the casing 50 has been run, operators prepare the rig for the cement job by “stabbing” the cement head 30 on the last joint of casing 50, as schematically illustrated in FIG. 2A. Due to the length of the cement head 30, longer bales may be required for the traveling block at the rig.

With the cement head 30 installed, cementing operations can then commence. In particular, operators rig up the cementing lines 36 to the plug launchers 32 a-b of the cement head 30. The lowest valve 34 a is opened, and the two top most valves 34 b-c are closed. Operators then break circulation with the cement unit (not shown) and then close the lower valve 34 a and open the middle valve 34 b. The retaining stem 38 a supporting the bottom plug 80 is backed out of the plug launcher 32 a, and the bottom plug 80 is “kicked out” with about 5-10 bbls of water. Operators watch for the tattle tail indicator to trip to verify that the bottom plug 80 has left the plug launcher 32 a, and operators reset the indicator.

FIG. 2B schematically illustrates the well assembly with the bottom plug 80 deployed during the cementing operation. Cement is mixed and pumped as required. As shown in FIG. 2B, a spacer S follows the bottom plug 80 as it displaces the original mud in the casing 50 and the borehole 10. For example, the casing 50 above the float collar 60 may be filled with drilling mud or completion fluid—i.e., KCL, CaCl, etc. A cement slurry C pumped from the lines 36 follows the spacer S, pumping the bottom plug 80 down the casing 50.

Eventually, enough cement slurry C is pumped that operators release the gun-on-plug assembly 100 from the cementing head 30. As shown in FIG. 2C, operators close the middle valve 34 b and open the top valve 34 c on the head 30. The upper retainer stem 38 b is backed out, and the gun-on-plug assembly 100 is “kicked out” of the upper launcher 32 b with about 5 bbls of fresh water. The tattle tail indicator will trip to verify that the assembly 100 has left the cement head 30.

The gun-on-plug assembly 100 is displaced down the casing 50 as the displacement fluid D is pumped behind the assembly 100 so the plug 110 can displace the cement C. Preferably, the pump rates do not exceed a maximum threshold (e.g., about 10 bbls per minute). Additionally, the pump rate is preferably slowed to a rate of about 2 bbls per minute within about 15 bbls before the gun-on-plug assembly 100 reaches the float collar 60.

As shown in FIG. 2D, the bottom plug 80 eventually lands on the float collar 60, and its central opening is breached. For example, a rupture disc or the like in the plug 80 can break, permitting the cement C to pass through the open plug 80, the float collar 60, and the float shoe 70. The pumped cement C then enters the annulus between the borehole 10 and casing 50. Typically, the bottom plug 80 has a “pump out” pressure of about 500-psi. By contrast, the top plug 110 is solid and has a 5000-6000-psi rating depending on size.

Eventually, as shown in FIG. 2E, the top plug 110 engages or lands on the bottom plug (if used) or the float collar 60. The interface between the float collar 60 and the plug 110 can incorporate a latching mechanism, a catch, or the like. As such, known latching mechanisms can be used between the float collar 60 and the plug 110. At this point, the cement slurry C has exited through the open bottom plug 80, float collar 60, and the float shoe and has passed into the annulus around the casing 50 to begin setting. Engagement of the top plug 110 with the bottom plug 80 closes off fluid communication.

With the gun-on-plug assembly 100 landed at the float collar 60, operators test the float collar 60 and hold pressure to keep the plug 110 in place. For example, operators can pressure up the casing 50 to about 3000-psi and hold this pressure for about 15 minutes. The pressure is then released to make sure the float collar 60 and float shoe 70 are holding. If they are not holding, operators pressure back to about 3000 psi and hold this for an extended period of time to ensure the cement C stays in place and sets properly.

Later during operations, operators are ready to complete the well. As shown in FIG. 2F, the rig and cement head are typically moved off, and a fracture tree 46 and other components can be installed at surface. Operators then rig up a treatment pump 48 at surface to pressurize the casing 50 and fire the perforating gun 120. Once these components are installed and the pump lines are tested, operators pressure up on the casing 50 to the maximum anticipated treatment pressure and hold it for a period of time (e.g., 30 minutes) to test the casing's integrity. The maximum treatment pressure for a fracture operation can reach as high as 15,000 psi, depending on the implementation.

Once testing is complete, operators activate the gun 120 to perforate the casing 50. Activation can use a number of hydraulic techniques. For example, the firing mechanism 150 may include electronics (i.e., detector) and power supply to detect coded pressure signals or pulses communicated down the casing 50 from the surface. These coded signals can use telemetry systems known and used in the art. Once the gun 120 detects the coded signal, the gun 120 can initiate the firing mechanism 150 to perform the perforating. Alternatively, detection of the coded signal may simply operate as an initiation signal that prepares the gun 120 to receive a subsequent coded activation signal, increased pressure, or some other initiating action.

Alternatively or in addition to the above-techniques, activation of the gun 120 may use communicated hydraulic pressure above a threshold level. In this case, operators continue to pressure up on the casing 50 after testing is complete. The pressure is built up to a point to reach the pressure required to activate the firing mechanism 150 in the gun 120. For example, the firing mechanism 150 may use one or more rupture discs or other mechanism therein that protects a firing head from pressure until breached by a predetermined pressure. At that point, the pressure may subsequently activate the firing mechanism 150. The particular pressure levels can be configured for an implementation.

As can be seen, the predetermined pressure to activate the firing mechanism 150 is preferably greater than the maximum anticipated treatment pressure to be used. Although the pressure levels can depend on the implementation, the pressures involved in testing and operations, and other factors, the predetermined pressure can be set about 1,000 psi above the maximum anticipated treatment pressure. Additionally, once the firing mechanism 250 is breached by the predetermined pressure, a greater, a lesser, or an equivalent pressure may subsequently activate the firing mechanism 150. Further details are discussed below.

Should the firing mechanism 150 fail to activate the gun 120, remedial steps can be taken to either initiate firing or correct the situation. For example, a drilling or milling unit can be deployed downhole through the casing 50 to the seated assembly 100. Milling at the top of the assembly 100 can breach any potential obstructions (residual cement, debris, etc.) preventing the fluid pressure from communicating to the firing mechanism 150. Moreover, the milling operation may be used to remove outer components and expose the inner components of the firing mechanism 150, allowing for direct application of casing pressure to activate the gun 120. For example, a rupture disc on or in the fishing neck 180 may be milled away so that fluid pressure or even mechanical impact can activate the firing mechanism 150. Finally, conventional tubing-conveyed perforating guns could be deployed to create the perforations for the initial flow path.

When the gun 120 is fired and perforations P are formed, however, the casing pressure declines, indicating that the casing 50 and set cement have been perforated, as shown in FIG. 2F. At this point, the perforations P provide communication between the casing 50 and the formation so operators can pump fracture treatment into the formation and commence with further completion operations.

In summary, the gun-on-plug assembly 100 provides operators with an initial flow path downhole in the casing 50 without requiring the costs associated with coil tubing, conventional tubing, or workover rigs. The assembly 100 is placed just above the float collar 60 when the casing 50 is cemented in the wellbore 10. Once the drilling rig is moved off location, operators are able to initially fire the guns 120, utilizing a pump truck or frac pump 46 prior to the beginning of the single or multi-stage frac program.

The complete assembly 100 is loaded into the cementing head 30 attached to the top of the casing 50. At the appropriate time during cementing of the casing 60, the gun-on-plug assembly 100 is released and is pumped down the casing 50 until the plug 110 seats at the float collar 60. The casing 50 may be pressure tested at this time, and pressure may or may not be held on the casing 50 while the cement cures. After a period of time, normally 12-24 hours any pressure may be bled off the casing 10. The drilling rig is moved off the wellsite.

When operators are ready to fire the gun 120, a wellhead 46, fracture tree, and pump 48 are installed at surface to pressure up the casing 50. The gun 120 is activated to perforate the casing 50 and create the initial flow path through the perforations P. This first zone Z₁ can then be treated with fluid treatment—e.g., fracture treatment.

Once this first zone Z₁ of the formation has been perforated and treated (e.g., fractured), operators can continue with other completion operations. For example, as shown in FIGS. 3A-3B, operators can retrieve the gun-on-plug assembly 100 from the well by retrieving the gun 120 with the plug attached 110, or the assembly 100 may be left in place. In another alternative, the gun 120 may be detached from the plug 110, provided a detachable connection is present. Either way, operators can set a bridge plug 94 in the casing 50 and can deploy a conventional perforating gun 96 to perforate the next zone Z₂, as is typically performed.

As shown in particular in FIG. 3A, a coiled tubing unit 90 can be used to deploy coiled tubing 92 (or a workover rig 90 can be used to deploy conventional tubing 92) into the casing 50 so that a coupling 98 can connect to the fishing neck 180 on the assembly 100. Once connected, the unit 90 can remove the assembly 100 from the well. This may include removing at least the gun 120. Depending on the attachment between the gun 120 and the top plug 110, the plug 110 may remain in the well or may be removed with the gun 120. Additionally, the bottom plug 80 will remain in the well.

Any components left in the well can be milled out during milling operations. Fracture or other treatments can be applied to the perforations P in the casing 50 to treat the surrounding zone Z₁ in the formation with proppant, acid, or the like.

With the gun 120 removed, a wireline unit 94 can then deploy and set a bridge plug 95 in the casing 50 to isolate the previously perforated zone Z₁ from uphole portions of the casing 50, as shown in FIG. 3B. Setting the bridge plug 95 with wireline 96 can use standard procedures know in the art for pump-down perforation operations. Because the initial flow path is open, the plug 95 can be pumped down on the wireline 96 to the desired depth.

In some cases, a perforating gun 97 is pumped down in conjunction with the bridge plug 95. Once the bridge plug 95 is set, the perforating gun 97 can be pulled by wireline 96 out of the wellbore to a desired depth at which point the gun 97 is fired. This procedure can continue until all of the perforations P have been made in the casing 50 for this next zone Z₂. Once the new perforations P are formed, the perforating gun 97 can be removed, and any fracture or other treatments can be applied to the new perforations P in the casing 50. Finally, the entire procedure can be repeated up the casing 50 to perforate multiple zones.

So far, the gun-on-plug assembly 100 has been generally illustrated. FIG. 4 illustrates components of a gun-on-plug assembly 200 according to one embodiment of the present disclosure. As before, the assembly 200 includes a perforating gun 220, a top casing wiper plug 210, and a fishing neck 280.

The fishing neck 280 installs on the top 224 of the perforating gun 220, and the bottom 222 of the perforating gun 220 attaches to the top plug 210. Operators can attach these components 210, 220, and 280 in the field, if desired, or they may be pre-assembled. Alternatively, these components 210, 220, and 280 can be made integral to one another. In the present embodiment, the bottom of the perforating gun 220 includes a threaded sub 222 that threads into a threaded pocket 212 in the top plug 210. The bottom sub 222 of the gun 220 may even incorporate components of a wiper to enhance the attachment between the gun 220 and the plug 210.

Preferably, the plug 210 is solid. A set screw or other fasteners can be used to make sure the gun 220 and plug 210 do not separate when pumped down the casing. Other forms of attachment could be used.

The fishing neck 280 affixes to the top of the perforating gun 220 using a threaded connection 224, although other forms of attachment can be used. The upper end of the fishing neck 280 has a standard profile 282 for being engaged by a fishing tool. To help centralize the perforating gun 220 as it is displaced down the casing along with the top plug 210, the fishing neck 280 may have centralizers 284. Alternatively, the housing of the perforating gun 220 can have centralizers.

The perforating gun 220 can be a scalloped-type of perforating gun. The perforating gun 220 is loaded with charges 226 and has a firing mechanism 250 to activate the charges 226. These charges 226 are disposed around the axis of the gun 220 to perforate the surrounding casing when activated. Many of the features of the perforating gun 220 can be similar to those commonly used. For example, the gun 220 can be loaded with charges 226 for one to six shots per foot (spf) and can use either deep penetrating (DP), big hole (BH), or other types of charges 226 with high temperature explosive components. Details of the particular implementation will determine the shots per foot and what type of charges 226 to use.

The firing mechanism 250 is hydraulically-actuated, being in fluid communication with surrounding casing pressure outside the gun 220 when deployed downhole. For example, the firing mechanism 250 may be attached toward the top of the perforating gun 220 and may communicate with one or more passages 286, ports, or the like in the fishing neck 280. Other configurations can be used to place the firing mechanism 250 in fluid communication outside the gun 220.

Exposed to external pressure, the firing mechanism 250 is configured to function at a specific predetermined casing pressure, which is adjustable via one or more shear pins, rupture discs, temporary connections, temporary barriers, or other temporary retainers. When activated hydraulically by this external pressure, the firing mechanism 250 initiates the detonation of a detonating cord 272 and the charges 226 within the gun 220.

FIG. 5 illustrates an embodiment of the firing mechanism 250 for the disclosed gun-on-plug assembly 200. In general, the firing mechanism 250 can be part of or can connect to the outer housing 221 of the gun 220. Either way, components of the firing mechanism 250 can connect to the gun's inner body 225, which is disposed in the gun's housing 221 and holds the charges 226.

The firing mechanism 250 includes a firing head assembly 260 disposed in an inner bore 252 of the mechanism 250. A piston or firing head 262 is carried within the bore 252 for movement from an initial position shown in FIG. 5 to a lower position (not shown), in which a firing pin 268 on the head 262 engages a percussive detonator 270.

The firing head 262 sealingly engages inside the bore 252 and can be held in the initial position using a number of features. For example, features such as retainer 264, shear pins 266, and shoulder 254 may be used. As shown, shear pins 266 can affix the firing head 262, but it will be appreciated that one or more other temporary retainers or connections may be used. Located a short distance below the piston's firing pin 268, the percussive detonator 270 connects to the detonating cord 272, which leads to the one or more charges 226 (only one being shown in FIG. 5).

Because the gun-on-plug assembly 200 is deployed in casing when cementing operations and casing integrity tests are performed, the firing mechanism 250 is preferably protected. Accordingly, a chamber 256 is disposed toward the top of the firing head 262. This chamber 256 is maintained at a lower (e.g., atmospheric pressure) located adjacent the firing head 262. The chamber 265 communicates externally and may or may not communicate with the fishing neck 280 on the assembly 200.

As shown in FIG. 5, for example, with the fishing neck 280 is disposed above the chamber 256, the neck 280 has a passage 286 or the like. The passage 286 may be ported with a central port and/or side ports to communicate casing pressure from the casing to the chamber 256.

The chamber 256 is separated from the borehole environment outside the assembly 200 by one or more rupture discs 288. Although a rupture disc 288 is shown, it will be appreciated that another type of temporary retainer or barrier can be used. Preferably, at least two rupture discs 288 are used for redundancy. The chamber 256 and the discs 288 protect the firing head 262 from any wellbore pressures until the rupture discs 288 are ruptured by a specific pressure. All the same, firing of the gun 220 preferably includes a time delay in the form of time delay fuses or the like. In this way, the time delay fuses can run for a period of time (e.g., at least 30 minutes) in the event the rupture discs 288 fail prematurely, exposing the firing head 262 during the casing tests.

When operators are ready to fire the gun 220, the pump at the surface is used to pressure up the casing, and the casing pressure is applied against the rupture discs 288 protecting the chamber 256. Pressure applied with the pump above the threshold of the discs 288 eventually ruptures the discs 288. If the rupture discs 288 fail for whatever reason, then milling operations can expose the chamber 256 to casing pressure.

Either way, once at least one of the discs 288 is breached, the chamber 256 is flooded with wellbore fluids. The pressure can then be increased to a maximum pressure to break shear pins 266 and release the head 262. The actuating pressure required for shearing the head 262 free can be set higher than the pressure for the rupture discs 288, although other pressure arrangements can be used. The fluid pressure in the chamber 256 moves the head 262 to drive the firing pin 268 against the detonator 270, which detonates the charges 226.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof. 

What is claimed is:
 1. A method of cementing and perforating casing in a borehole, comprising: pumping cement slurry down the casing and into an annulus of the borehole; pumping an assembly having a wiper and at least one charge down the casing behind the cement slurry; landing the assembly in the casing; applying hydraulic pressure in the casing; and perforating the casing by activating the at least one charge of the assembly with the hydraulic pressure applied in the casing.
 2. The method of claim 1, wherein pumping the cement slurry down the casing and into the annulus of the borehole comprises: pumping a plug down the casing in advance of the cement slurry; landing the plug in the casing; and opening fluid communication through the plug for passage of the cement slurry.
 3. The method of claim 2, wherein landing the plug in the casing comprises landing the plug adjacent a float collar disposed on the casing.
 4. The method of claim 2, wherein pumping the plug down the casing in advance of the cement slurry comprises pumping a spacer in the casing between the plug and the cement slurry.
 5. The method of claim 1, wherein pumping the assembly down the casing behind the cement slurry comprises pumping a displacing fluid down the casing after the assembly.
 6. The method of claim 1, wherein perforating the casing comprises first permitting the cement slurry in the annulus to cure before perforating at least the casing.
 7. The method of claim 1, wherein applying the hydraulic pressure in the casing comprises applying at least one coded signal with the hydraulic pressure in the casing.
 8. The method of claim 7, wherein activating the at least one charge of the assembly with the hydraulic pressure applied in the casing comprises detecting the at least one coded signal and at least initiating activation of the at least one charge for detonation in response thereto.
 9. The method of claim 7, wherein activating the at least one charge of the assembly with the hydraulic pressure applied in the casing comprises detecting the at least one coded signal and detonating the at least one charge in response thereto.
 10. The method of claim 1, wherein applying the hydraulic pressure in the casing comprises applying the hydraulic pressure at a first pressure level at least higher than a second pressure level for testing integrity of the casing.
 11. The method of claim 1, wherein applying the hydraulic pressure in the casing comprises applying the hydraulic pressure at a first pressure level at least higher than a second pressure level for fracturing.
 12. The method of claim 1, wherein activating the at least one charge with the hydraulic pressure applied in the casing comprises activating a firing head of the assembly with the applied hydraulic pressure.
 13. The method of claim 12, wherein activating the firing head of the assembly with the applied hydraulic pressure comprises breaking at least one first temporary retainer in the assembly separating the applied hydraulic pressure from the firing head.
 14. The method of claim 13, wherein activating the firing head of the assembly with the applied hydraulic pressure comprises breaking at least one second temporary retainer of the firing head with the applied hydraulic pressure after breaking the at least one first temporary retainer.
 15. The method of claim 14, wherein breaking the at least one second temporary retainer of the firing head with the applied hydraulic pressure after breaking the at least one first temporary retainer comprises breaking the at least one second temporary retainer with a higher level of the applied hydraulic pressure than used to break the at least one first temporary retainer.
 16. The method of claim 1, wherein pumping the assembly down the casing behind the cement slurry comprises deploying the assembly from a cement head at surface.
 17. The method of claim 1, further comprising retrieving at least a portion of the assembly from the casing after perforating the casing.
 18. The method of claim 1, further comprising: deploying a bridge plug in the casing uphole of the perforation; and perforating the casing further uphole using another perforating gun.
 19. The method of claim 1, wherein landing the assembly in the casing comprises testing integrity of the casing by applying intermediate hydraulic pressure in the casing behind the assembly.
 20. The method of claim 19, further comprising delaying activation of the at least one charge should the intermediate hydraulic pressure activate the at least one charge.
 21. An apparatus used in cementing and perforating casing in a borehole, the apparatus comprising: a plug; a perforating gun attached to the plug and having one or more charges; and a firing mechanism disposed on the perforating gun and coupled to the one or more charges, the firing mechanism in fluid communication with the casing and being activated hydraulically to detonate the one or more charges.
 22. The apparatus of claim 21, further comprising a bottom plug independent of the plug and deploying in the casing in advance of the plug, the bottom plug having a breachable passage therethrough.
 23. The apparatus of claim 21, further comprising a fishing neck disposed on a proximal end of the perforating gun.
 24. The apparatus of claim 21, further comprising a cement head having launchers, at least one of the launchers accommodating the perforating gun attached to the plug.
 25. The apparatus of claim 24, wherein the firing mechanism is hydraulically activated in response to at least one coded signal applied with hydraulic pressure in the casing.
 26. The apparatus of claim 25, wherein the firing mechanism at least initiates activation of the one or more changes for detonation in response to the at least one coded signal.
 27. The apparatus of claim 25, wherein the firing mechanism detonates the one or more charges in response to the at least one coded signal.
 28. The apparatus of claim 21, wherein the firing mechanism comprises: a detonator connected to the one or more charges; a pin exposed to a chamber and movable toward the detonator; and at least one first temporary retainer separating the chamber from external pressure in the casing.
 29. The apparatus of claim 28, wherein the pin comprises at least one second temporary retainer holding the pin away from the detonator.
 30. The apparatus of claim 29, wherein the at least one second temporary retainer releases the pin at a higher level hydraulic pressure than used to break the at least one first temporary retainer.
 31. The apparatus of claim 29, wherein the at least one second temporary retainer comprises at least one shear pin, and wherein the at least one first temporary retainer comprises at least one rupture disc.
 32. The apparatus of claim 21, wherein a distal end of the perforating gun threads to a top of the plug.
 33. The apparatus of claim 21, wherein the plug and the perforating gun are formed integrally together.
 34. An apparatus used in cementing and perforating casing in a borehole, the apparatus comprising: a cement head disposed on the casing and having first and second launchers; a bottom plug positioning in the first launcher and deploying from the cement head in the casing in advance of cement slurry; an assembly positioning in the second launcher and deploying from the cement head in the casing after the cement slurry, the assembly having a wiper and having one or more charges, the wiper wiping the casing, the one or more charges being activated hydraulically with pressure in the casing to perforate the casing. 